Method and system for preventing clathrate hydrate blockage formation in flow lines by enhancing water cut

ABSTRACT

The present invention includes a method for inhibiting hydrate formation blockage in a flow line used to transport hydrocarbon containing fluids. Water is added to a hydrocarbon containing fluid to produce a water cut enhanced hydrocarbon containing fluid. Salt may be added to the hydrocarbon containing fluids as well. Hydrate formation blockage is inhibited from forming within the flow line by the addition of the water and/or the salt. Sufficient water may be added such that the hydrocarbon containing fluid is converted from a water in oil emulsion to a water continuous emulsion. A system for preventing the formation of hydrate blockage in conduits is also provided. The system includes a flow line for transporting a hydrocarbon containing fluid and a water injection conduit fluidly connected to the flow line to add water to the flow line to increase the water cut of a hydrocarbon containing fluid flowing through the flow line. A salt dispenser may also be included which is used to increase the salinity of the hydrocarbon containing fluid. The system may further include a water separator to separate hydrocarbons from water which receives fluids from the flow line. The flow line, water separator and water injection conduit may cooperate to form a loop wherein water from the flow line may be separated by the water separator and a portion of the separated water is delivered back to the water injection conduit to be reinjected into the flow line.

TECHNICAL FIELD

The present invention relates to preventing the formation of clathratehydrate blockages in flow lines or conduits carrying hydrocarbons.

BACKGROUND OF THE INVENTION

Clathrate hydrate plug formation in oil and gas pipelines is a severeproblem for the petroleum industry. When water is produced along withgas, oil, or mixtures of both, under the right pressure and temperatureconditions, there is a potential to form a solid hydrate phase.Pressure-temperature conditions favorable for hydrate formation arecommonly encountered during the winter in fields onshore and in shallowwater depths offshore, and regularly in deepwater (>1,500 feet waterdepth) fields offshore. As a rule of thumb, at a seafloor temperature ofabout 40° F. for water depths greater than 3,000 feet, hydrates can formin a typical natural gas pipeline at pressures as low as 250 psi. Assolid hydrates form, the hydrates can deposit on the pipe walls oragglomerate into larger solid masses creating obstructions to flow.

Technologies currently used to prevent hydrate blockage formationinclude dehydration, heat and/or pressure management or chemicalinjection with thermodynamic or low dosage hydrate inhibitors (LDHI).Dehydration is simply removing most of the water from the hydrocarbonstream so that too little is left to form hydrate blockages. Temperatureor pressure control is used to operate a system outside of conditionsthat can promote hydrate formation. The addition of thermodynamicinhibitors (typically alcohols, glycols or salts) produces ananti-freeze like effect that shifts the hydrate phase equilibriumcondition to lower temperatures at a given pressure so that a system maybe operated safely outside the hydrate stability region. LDHI act in oneof two ways: 1) as a kinetic inhibitor, or 2) as an anti-agglomerant.Kinetic LDHIs merely slow the hydrate formation rate so that formationof a solid blockage is retarded during the residence time of the fluidsin the pipeline. Anti-agglomerant LDHIs allow the hydrates to form, butkeep the hydrate particles dispersed in a liquid hydrocarbon phase.Anti-agglomerant LDHIs are also known to have limitations on the watercut in which the chemicals can work. They are usually recommended forapplication for water cuts of less than 50%.

Each of these solutions for hydrate prevention can work, but all requiresignificant capital or operating expense. The thermal and dehydrationoptions are capital intensive, the thermodynamic inhibitor options areboth capital and operationally intensive, and the LDHI option isoperationally intensive. LDHIs also have additional risk associated withtheir application due to the relative immaturity of the technology.Additionally, discharge water quality (toxicity) and crude quality(methanol content for example) issues can be a concern when using boththermodynamic inhibitors and LDHIs. There is also a general concern inthe industry that as remote deepwater fields mature, water cuts maybecome high to the point where chemical injection for hydrate inhibitionmay offer considerable challenges—either due to the sheer volumes ofthermodynamic inhibitor required or due to limitations on LDHIperformance as mentioned above. Therefore, the issue of a cost-effectiveand reliable hydrate inhibition strategy for fields with high water cutsis a major challenge facing the industry.

There are additional flow assurance issues commonly found withlow-temperature high pressure flow in flow lines. In cases where thereis water in an oil emulsion, such an emulsion can have high viscosityleading to problems associated with excessive pressure drop. The presentinvention, to be described hereafter, addresses the challenges describedabove.

SUMMARY OF THE INVENTION

The present invention includes a method for inhibiting hydrate formationblockage in flow lines used to transport hydrocarbon containing fluids.Water is added to a hydrocarbon containing fluid to produce a water cutenhanced hydrocarbon containing fluid. The water cut enhancedhydrocarbon containing fluid is then transported by a flow line. Hydrateformation blockage is inhibited from forming within the flow line by theaddition of the water which tends to lower the hydrate phase equilibriumtemperature for a given pressure of the hydrocarbon containing fluid andflow velocity.

Preferably, the resulting water cut enhanced hydrocarbon containingfluid is water continuous. Sufficient water may be added such that thehydrocarbon containing fluid is inverted from a water in oil emulsion toa water continuous emulsion state thereby decreasing emulsion viscosityand reducing pressure drop in the flow line.

Sufficient water may be added such that the water cut of the water cutenhanced hydrocarbon containing fluid is at least 50%, and possibly even75% or 85%. The hydrate thermal equilibrium temperature of the water cutenhanced hydrocarbon containing fluid may be lowered 2.5° F., 5.0° F.,or even 10° F. as compared to the original hydrocarbon containing fluid.

Further, sufficient water may be added to the original hydrocarboncontaining fluid such that there is an excess of the water phaserelative to the hydrocarbon phase such that hydrate formation is selflimiting. This occurs when the hydrocarbon hydrate forming componentsare exhausted through hydrate formation and a flowing slurry ofhydrates, hydrocarbons and water results.

Salt may be added to increase the salinity of the water cut enhancedhydrocarbon containing fluid. The weight % of salt in the water cutenhanced hydrocarbon containing fluid may be 5%, 10% or even 15% orhigher.

A system for preventing the formation of hydrate blockage in flow linesis also provided. The system includes a flow line for transporting ahydrocarbon containing fluid and a water injection conduit fluidlyconnected to the flow line to add water to the flow line to increase thewater cut of the fluid flowing through the flow line. The flow lineshould be connected to a hydrocarbon source and the water injectionconduit fluidly connected to a water source. The system may be operablein an environment sufficiently cool such that hydrate blockage mightform absent the addition of water to the hydrocarbon containing fluidfrom the water injection conduit. The hydrocarbon source may be a wellbore from which hydrocarbons are produced. The water source may seawater, a sub sea water well or a water storage tank mounted on anoffshore platform. Alternatively, the system may be used on land wherehydrocarbon containing fluids are to be transported in flow lines andthe flow lines are exposed to cold temperatures.

The system may further include a water separator to separate water fromhydrocarbons received from the flow line. The flow line, water separatorand water injection conduit may cooperate to form a partially closedloop wherein water from the flow line may be separated by the waterseparator and delivered back to the water injection conduit to bereinjected into the flow line to enhance the water cut of thehydrocarbon containing fluid.

It is an object of the present invention to provide a method and systemto address multiple flow assurance issues (hydrate inhibition, emulsionviscosity/stability, system thermal performance, and system hydraulicperformance) through a simple, cost-effective, and environmentallyfriendly strategy.

It is another object to provide a method for multiphase production ofcrude oil and natural gas wherein hydrocarbon containing fluids aretransported through a flow line at unconventionally high water cuts tothereby reduce hydrate blockages in the flow line relative to usinghydrocarbon containing fluids having a lower water cut.

BRIEF DESCRIPTION OF THE DRAWINGS

These and other objects, features and advantages of the presentinvention will become better understood with regard to the followingdescription, pending claims and accompanying drawings where:

FIG. 1 is a graph showing the thermodynamic effect of water cut andbrine salinity on the hydrate stability region of a heavy oil;

FIG. 2 is a graph showing the general change in viscosity of emulsionsas a function of water cut;

FIG. 3 is a first embodiment of a hydrate blockage inhibiting systemwhich includes a water injection conduit which injects water and/or saltinto a sub sea wellhead tree to enhance the water cut of a hydrocarboncontaining fluid carried by a flow line to a floating platform in a sea;

FIG. 4 is a second embodiment of a hydrate blockage inhibiting systemwhich includes water injection into a sub sea manifold;

FIG. 5 is a third embodiment of a hydrate blockage inhibiting systemwhich includes water injection at a riser base;

FIG. 6 is a fourth embodiment of a hydrate blockage inhibiting systemusing a submersible pump to inject sea water into a wellhead tree;

FIG. 7 is a fifth embodiment of a hydrate blockage inhibiting systemusing a submersible pump to inject sea water into a sub sea manifold;and

FIG. 8 is a sixth embodiment of a hydrate blockage inhibiting systemwhich injects water from a sub sea well into a production fluidcollected from a fresh water sub sea well.

BEST MODE(S) FOR CARRYING OUT THE INVENTION

The present invention is counterintuitive and surprising in that itcalls for adding excess water to a hydrocarbon containing fluid toinhibit hydrate blockage formations in flow lines of a system.Conventional wisdom is to remove water and/or add chemical hydrateinhibitors. This process of purposely adding water, which is abundantlyavailable in offshore operations, may be a cost-effective, reliablehydrate blockage inhibition strategy with several potential additionalside benefits. The present invention may also be used on land as well toinhibit hydrate formation blockages where hydrocarbon containing fluidsare transported along a flow line exposed to cold temperatures.

This invention applies to multiphase flow systems where formation ofhydrate plugs or other significant hydrate obstructions in flow linesare a concern. Ideally, water, and possibly salt or brine, is added to ahydrocarbon containing fluid such that a water continuous phase ispresent (high water cut). The addition of the water and salt to thehydrocarbon containing fluid ideally addresses multiple flow assuranceissues (hydrate inhibition, emulsion viscosity/stability, system thermalperformance, and system hydraulic performance) through a simple,cost-effective, and environmentally friendly strategy.

Following this strategy, injection of water could be used to operatesystems in a water continuous emulsion state, thereby decreasingemulsion viscosity and reducing pressure drops in pipe lines or flowlines. This could be beneficial especially for heavy oils that may beprone to forming high viscosity water in oil emulsions at cold sub seaconditions. Further, if a high salinity brine is injected instead offresh water, separation problems topside due to emulsions could bepotentially alleviated, or at least reduced, since salt can have anemulsion breaking effect depending on the characteristics of theemulsion.

Recent evidence discovered through experiments and modeling with heavyoils (˜20° API) suggests that hydrate equilibrium temperatures arereduced as water cut increases. The term “hydrate equilibriumtemperature” means the temperature at which hydrates will readily formfor a given composition of a hydrocarbon containing fluid at aparticular pressure and flow rate. The effect of increasing water cut tolower hydrate equilibrium temperature can be found in most hydrocarbonsystems and is unique for each particular composition of hydrocarboncontaining fluid. For example, compositions may contain mostly naturalgas or else predominantly heavy oils. The effect is more pronounced forheavy oils which tend to have low GORs (gas-to-oil ratio) and low bubblepoints.

FIG. 1 shows the thermodynamic effect of water cut and brine salinity onthe hydrate stability region of a heavy oil (˜20° API). In this example,increasing the water cut (no salt present) from 10% to 75% reduceshydrate equilibrium temperature at pressures above the bubble point byapproximately 2.5° F.; increasing the water cut from 75% to 85% reducesthe hydrate equilibrium temperature by another 2.2° F.

Also, illustrated is the enhanced thermodynamic effect achieved byadding brine instead of fresh water to lower the thermal equilibriumtemperature. For the heavy oil, increasing the water cut from 10% to 75%by adding brine with 7 weight % NaCl, as opposed to water with no salt,reduces hydrate equilibrium temperature above the bubble point by 7° F.compared to 2.5° F. when adding fresh water only. Adding brine with 15weight % NaCl reduces the hydrate equilibrium temperature above thebubble point by 15° F. compared to the 10% water cut, fresh water case.

FIG. 2 shows a general change in viscosity of emulsions as a function ofwater cut. As water cut is increased, a water in oil emulsion can beconverted to an oil in water emulsion. The graph shows that viscosity ofa water in oil emulsion is usually considerably higher than that of anoil in water emulsion at high water cuts (>than 70% water cut). This isespecially pronounced in case of heavy oil systems. At water cuts ashigh as 90%, viscosity is close to that of water.

In addition to the above thermodynamic effect, it is anticipated that byhaving an excess of the water phase relative to the hydrocarbon phase inthese high water fraction systems, any hydrate formation reaction wouldbe self limiting as hydrate forming components (lighter hydrocarbons) inthe flow stream are exhausted. The result is expected to be an oil andhydrate in water slurry. Within certain operating conditions of fluidflow velocity, system geometry, water cut, and temperature and pressurethe oil and hydrate in water slurry should remain flowable.

As already mentioned, brine also enhances the thermodynamic effect onhydrate stability produced by adding water to the system. Water alsoimproves heat retention thereby improving thermal performance of thesystem which might be helpful for mitigating certain flow assuranceissues. Switching to water or high salinity brine injection as thehydrate inhibition strategy is also expected to reduce chemicalinhibitor presence in water and the oil phase. This will havesignificant benefits for topside water clean up and should result inreduced penalties imposed on an operator by downstream refineries due tothe elimination of methanol from crude oil. Therefore, the proposedstrategy is also a more environmentally friendly hydrate inhibitionstrategy as compared to the current thermodynamic and/or LDHI inhibitorinjection strategy since storage, handling, and processing of flammable(methanol), potentially toxic (anti-agglomerant LDHIs) chemicals can beeliminated from offshore operations.

FIG. 3 illustrates a first exemplary embodiment of a hydrate blockageinhibition system 20 which is constructed in accordance with the presentinvention. An offshore platform 22 is located in a sea 24 disposed abovea sea floor 26. A well bore 30 is located in a sub sea formation 32.Perforations 34 in well bore 30 allow hydrocarbon containing fluids tobe extracted from formation 32. Located atop well bore 30 is a sub seatree 36. Tree 36 passes a hydrocarbon containing fluid from well bore 30to a production flow line or pipeline 40. A sub sea manifold 42 isdisposed intermediate tree 36 and platform 22.

Platform 22 supports a separator 44 which separates water from thehydrocarbon containing fluid received from flow line 40. The separatedwater may be disposed of in conventional fashions such as dumping thewater into sea 24 after being cleaned to an environmentally acceptablequality. Alternatively, a substantial portion of the separated water orbrine solution may be directed to a water injection flow line 46 whichsupplies water to be added to the hydrocarbon containing fluid receivedfrom well bore 30. In this instance, the added water is injected into aport (not shown) plumbed into tree 36. Separated oil exits fromseparator 44 through an oil discharge line 48. Although, not shown, aseparate gas discharge line may also be employed when substantialamounts of gas are produced and are separated by separator 44.

A meter 50 measures and controls the quantity of water which is beingpassed from separator 44 to a pump 52. Pump 52 is used to increasepressure in the water passing through water injection conduit 46 andwhich is injected into the produced hydrocarbons from well bore 30. Saltmay also be added to water injection flow line 46 from a salt dispenser53, preferably as a brine such as a sodium chloride in water solution.In this exemplary embodiment, the water is injected into tree 36. Awater conduit 54 connects separator 44 and pump 52. A water dischargeconduit 56 is used to discharge surplus separated water which is not tobe reinjected to enhance the water cut of the produced hydrocarboncontaining fluid from well bore 30.

The produced hydrocarbon containing fluid from well bore 30 typicallyarrives at tree 36 from well bore 30 at a particular pressure and at atemperature which is significantly above the temperature suitable forhydrate formation. However, as the produced fluid travels to sub seamanifold 42 and up production flow line 40, the cold sea waterssurrounding flow line 40 may cool the produced hydrocarbon containingfluid sufficiently that hydrate formation blockage may be a significantpossibility. That is, the production hydrocarbon containing fluids mayenter into the hydrate stability region for the particular compositionof oil, gas, water, and other constituents of the produced fluids fromwell bore 30.

In operation, the amount of water/brine solution added to the producedhydrocarbon containing fluid is dependent on the desired characteristicsof the water cut enhanced hydrocarbon containing fluid. For example, ifthe produced hydrocarbon containing fluid from well bore 30 is at a lowwater cut, i.e., the produced fluid is an oil emulsion containing wateror has a hydrocarbon continuous phase, then sufficient water/brinesolution may be added to invert the fluid into a water continuous, watercut enhanced hydrocarbon containing fluid. This addition of water may besufficient to drop the hydrate equilibrium temperature 2.5° F., 5.0° F.,10° F. or even 15° F., depending on how much water and salt is added tothe production fluids being injected into tree 36. Also, it may bepermissible to allow hydrate formation to readily occur if sufficientwater and salt are added to maintain the water cut enhanced productionfluid in a slurry state where individual hydrate particles are suspendedin a water continuous fluid. Accordingly, blockages formed by hydrateswill be avoided in production pipeline 40 which might otherwise occurabsent the addition of the water and/or brine to the produced fluidsfrom well bore 30.

FIG. 4 shows a second exemplary embodiment of a system 120 which issimilar to that of the first embodiment shown in FIG. 1. Like componentsof the system have been given the same reference numerals as in thefirst embodiment. In this instance, the added water/salt is addeddownstream of the tree 36 with injection occurring into sub sea manifold42.

FIG. 5 shows a third embodiment of a system 220 wherein water/salt isinjected downstream of tree 36 and sub sea manifold 42 directly into theproduction pipeline at the base of a riser. The added water/salt shouldbe injected into production pipeline sufficiently upstream of where thecold sea water could potentially drop the temperature of the productionfluid to where hydrate phase stability conditions may exist.Accordingly, the beneficial effects provided by the introduction ofadded water and salt should be obtained before hydrate formationblockage can occur.

FIGS. 6 and 7 show respective systems 320 and 420 wherein a submersiblepump 60 gathers sea water and adds the extra water to production fluidsto inhibit hydrate formation blockage. In system 320, the extra water isadded to tree 36. In system 420, the extra water is added into the subsea manifold 42. The advantage of using these systems 320 and 420 isthat no lengthy water injection flow line 46 need be run from platform22 to sea floor 26. A disadvantage is that additional amounts of waterseparated by separator 44 must be disposed because no water isreinjected into flow line 40.

FIG. 8 shows a system 520 wherein fresh water is injected into theproduction flow line 40. Production fluids from well bore 30 arecollected by sub sea manifold 42. In this exemplary embodiment, a waterwell 62 is drilled into the sub sea formation 64 to provide a source ofwater. A well head 66 controls flow from well 62. Preferably, the sourceof water is fresh water having little brine. The water then can be addedto the production fluid anywhere from downstream of the production zone,i.e. where perforations 34 are located to just upstream of where thereis a significant potential for hydrate formation blockage to occur. Inthis particular exemplary embodiment, the added water is plumbed intosub sea manifold 42. Although not shown, a subset salt dispenser couldalso be used in embodiments 320, 420 and 520 if so desired to enhancethe salinity of the water cut enhanced hydrocarbon containing fluids.

In a manner similar to that described above, the present invention couldbe used to add water to hydrocarbon containing fluids flowing inpipelines on land or elsewhere where hydrate formation blockage is aconcern. For example, the pipeline may be operating in a cold and harshenvironment such as in Alaska or Canada where plugging of pipelines andother conduits with hydrate formations is problematic.

In summary, this invention calls for multiphase production of crude oiland natural gas at high water cuts, possibly adding water/brine toforcibly push a flow system to higher water cuts. It is expected thisstrategy will allow operators to address multiple flow assurance issues(hydrate inhibition, emulsion viscosity/stability, system thermalperformance, and system hydraulic performance) through a simple,cost-effective, environmentally friendly strategy.

While in the foregoing specification this invention has been describedin relation to certain preferred embodiments thereof, and many detailshave been set forth for purpose of illustration, it will be apparent tothose skilled in the art that the invention is susceptible to alterationand that certain other details described herein can vary considerablywithout departing from the basic principles of the invention.

1. A method for inhibiting hydrate formation blockage in a flow linetransporting a hydrocarbon containing fluid, the method comprising:adding water to a hydrocarbon containing fluid to produce a water cutenhanced hydrocarbon containing fluid; and transporting the water cutenhanced hydrocarbon containing fluid through a flow line underconditions that would be conducive for the formation of hydrates in theoriginal hydrocarbon containing fluid; whereby hydrate formationblockage is inhibited from forming within the flow line by the additionof the water.
 2. The method of claim 1 wherein: sufficient water isadded such that the water cut of the water cut enhanced hydrocarboncontaining fluid is at least 50%.
 3. The method of claim 1 wherein:sufficient water is added such that the water cut of the water cutenhanced hydrocarbon containing fluid is at least 75%.
 4. The method ofclaim 1 wherein: sufficient water is added such that the water cut ofthe water cut enhanced hydrocarbon containing fluid is at least 85%. 5.The method of claim 1 wherein: sufficient water is added to lower thehydrate equilibrium temperature of the water cut enhanced hydrocarboncontaining fluid by at least 2° F. relative to the original hydrocarboncontaining fluid.
 6. The method of claim 1 wherein: sufficient water isadded to lower the hydrate equilibrium temperature of the water cutenhanced hydrocarbon containing fluid by at least 5° F. relative to theoriginal hydrocarbon containing fluid.
 7. The method of claim 1 wherein:salt is added to the water to increase the salinity of the water cutenhanced hydrocarbon containing fluid.
 8. The method of claim 7 wherein:the weight % of salt in the water cut enhanced hydrocarbon containingfluid is at least 5%.
 9. The method of claim 7 wherein: the weight % ofthe salt in the water cut enhanced hydrocarbon containing fluid is atleast 10%.
 10. The method of claim 7 wherein: the water phase of thewater cut enhanced hydrocarbon containing fluid is continuous; and thewater cut enhanced hydrocarbon containing fluid has a weight % of saltof at least 5%.
 11. The method of claim 1 wherein: the water is added tothe hydrocarbon containing fluid at a sub sea location.
 12. The methodof claim 1 wherein: sufficient water is added such that hydrateformation is self limiting as hydrocarbon hydrate forming components inthe water cut enhanced hydrocarbon containing fluid are exhaustedthrough the formation of hydrate particles.
 13. The method of claim 1wherein: sufficient water is added such that the hydrocarbon containingfluid is converted from an water in oil emulsion to a water continuousemulsion thereby decreasing emulsion viscosity and reducing pressuredrop in the flow line.
 14. A system for preventing the formation ofhydrate blockage in a flow line, the system comprising: a flow line fortransporting a hydrocarbon containing fluid; a water injection conduitfluidly connected to the flow line to add water to the flow line; and ahydrocarbon source which is in fluid communication with the flow line toprovide a hydrocarbon containing fluid to the flow line; wherein watermay be added to the flow line from the water injection conduit toenhance the water cut of the hydrocarbon containing fluid.
 15. Thesystem of claim 14 wherein: the hydrocarbon source is a well bore. 16.The system of claim 14 further comprising: a water source fluidlyconnected to the water injection conduit; and the water source is one ofsea water, a sub sea water well or a water source mounted on an offshoreplatform.
 17. The system of claim 14 further comprising: a waterseparator fluidly connected to the flow line to receive fluidscontaining hydrocarbons and water, the water separator being capable ofseparating water from hydrocarbons.
 18. The system of claim 17 wherein:the flow line, water separator and water injection conduit cooperate toform a loop wherein water from the flow line may be separated by thewater separator and delivered back to the water injection conduit to bereinjected into the flow line.
 19. The system of claim 14 furthercomprising: a salt dispenser which connects relative to the flow line sothat salt may be added to increase the salinity of the hydrocarboncontaining fluid.